I recently profiled capital expenditure trends in the Delaware Basin and the Haynesville, so I thought it would be a good time to delve into the Eagle Ford. In this insight I track capex in the traditional core of the play, the Karnes Trough, located largely in Karnes and De Witt counties in Texas.
Our data sources are faily simple and detailed in the other insights.
- Capex, Production, and Well Locations/Laterals comes from the Railroad Commission.
- Completion data (proppant/fluid/TVD) comes from Frac Focus.
The capex data is limited to wells either classified as gas or gas condensate (>11,500 ft True Vertical Depth), so the shallower portions of Karnes Trough will not be represented. For this reason I will not be digging into individual operator trends, as it is likely not representative of the entire asset base.
However, the data set is sufficient to do overall trend analysis.
Figure 1: Karnes Trough Well Coverage
I will step through a bit of the data and general trends before digging in a bit deeper.
Ensign leads the list, though in reality most of these wells were drilled by Pioneer. Folks that also typically exist in the gas condensate window are Marathon and Devon, while Repsol bought out partner Equinor last year.
Figure 2: Karnes Trough Operator Coverage
Lateral lengths, maybe surprisingly, haven’t moved too much. Some of this may be driven by lease constraints, and some may be due to higher depths/pressures.
Figure 3: Karnes Trough Lateral Length
While lateral lengths have barely budged, proppant loading has been steadily increasing each year.
Figure 4: Karnes Trough Proppant Loading
Overall, capex aggressively dropped going into the 2014/2015 price crash, but bottomed afterwards. In recent years, it has been trending higher.
Figure 5: Karnes Trough Total Capex
Though I did point out that lateral lengths were generally flat, I may as well look at it on a per-ft basis.
Figure 6: Karnes Trough Capex Per Ft
Once again, bottomed out in 2016 but has been trending higher as prices somewhat recovered. Of course, it will be interesting to see how 2020 fares as deflation will worm its’ way into the system.
Per LB of Proppant
Operators have been increasing total proppant loading, so I will look into cost per lb of sand pumped.
Figure 7: Karnes Trough Capex Per Thousand LBS of proppant
2019 did mark the low point from this perspective, but the data generally supports looking at wells since 2016 to give us a view of the various drivers for costs.
9-Month Finding & Development
Given that the leases are classified as gas, I have full production data from the state by well. For a quick look at economics, I’ll concentrate on Finding & Development Costs, though by using 9-month cumulative production instead of EUR’s.
For those that aren’t aware, F&D is capex divided by volume. I will also be using a 15:1 gas to oil conversion to estimate economic value of the gas stream.
Figure 8: Karnes Trough F&D Costs over Time
So I see a trend of bottoming costs, though this is in light of more intense completions. Overall F&D costs have flatlined as well.
Trends are interesting, but let’s dig a bit more into the various drivers, looking at wells brought online after 2016.
As with the other plays, it appears that moving from a 1-mile to 2-mile lateral results in a ~30% reduction in per-ft capex.
Figure 9: Karnes Trough Cost vs Lateral Length Post 2016
What does it do for Finding & Development costs? If I subset post 2016 by only recent vintage type completions (1500-2500 lb/ft proppant loading), I can get a view on how this trends.
Figure 10: Karnes Trough Lateral Length vsF&D Post 2016
It does seem to improve, but the increase above 7000 ft lateral lengths seems to imply that going too long leads to worse economic performance. Is this due to too small of a sample set? Maybe; there is between 20-40 wells in each ‘bin’. The completion designs are on average similar, so perhaps some is due to well issues as Total Depth increases. Regardless, this is a trend I will start looking into in other more densely drilled areas.
Does higher proppant loading actually lead to better well economics? To investigate, I will look at post 2016 wells with lateral lengths between 4500-6500 ft (the most common).
Figure 11: Karnes Trough Proppant Loading vs 9-month F&D Post 2016
The answer appears to be yes…..for a little while. However going well above 2000 lbs/ft seems to be detrimental. Based on a lot of the work I have done in the past, this makes perfect sense. At a certain point, each incremental lb of sand you pump yields little to any incremental barrels, but it certainly adds incremental costs.
That is it for this edition of Tracking Capex. It will be interesting to see how costs move in the Eagle Ford in 2020 with the large price drop this year. I’d caution that this probably isn’t sustainable, especially on the service side, so when prices rise again we will see an increase in capex as well.
This data is available and can be visualized at our sister site, AFE Leaks. We also offer the full dataset of 26,000+ wells in Texas and Louisiana covering plays such as the Delaware, Eagle Ford, Haynesville, and Barnett for purchase.
You can find the other insights in this series below.
The Delaware Basin is one of the most active shale basins in the US Lower 48. As compared to its’ cousin, the Midland Basin, the play is deeper and higher pressure. These two components typically drive well costs higher. In this insight I will delve into the cost drivers and trends in the basin. Follow …
What is driving Haynesville Capex costs? Read to find out more.